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draft imotp 121 9b discussion paper market incentives to increase

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					                                                      DRAFT
                                                                                                   IMOTP 121-9b
                                                Discussion Paper
     Market Incentives to Increase Amount of Dispatchable Generation Resources On-Line
                                   During Shoulder Periods


1.    Background
      a)   The IMO-administered markets characteristically select and schedule “just enough”
           resources to meet energy and operating reserve demands. If there is any disturbance or
           change1, even minor, to market or system conditions, the impact on the market and on
           supply resources can be dramatic. Market prices can fluctuate greatly (and in some
           circumstances, change counter-intuitively2), out of proportion to the disturbance or
           change to the market or system conditions. The resulting re-dispatch of scheduled
           resources can result in large swings in output, causing potential reliability,
           environmental, safety and equipment damage issues. Both the IMO and market
           participants have expressed concern over these dramatic fluctuations in market prices
           and significant dispatch volatility of facilities. Refer to Attachment A for representative
           examples of the dramatic price impacts from 2 days in September 2002.
      b) There have been some situations where these disturbances occurred and there were
         additional market resources available, but not selected and scheduled. Had some of
         these resources been operating in real-time, the market and system would have had
         some “shock absorption” capability to address the disturbances without the dramatic
         market and resource impacts. This situation occurs typically in “shoulder” periods, that
         is times when market demands are such that all domestic resources are not required to
         be operating: e.g. spring and autumn; off-peak hours in summer and winter. Frequency
         of these shoulder periods is expected to increase in 2003 as additional generation
         resources are brought back into service and commissioning generation is brought on-
         line.
      c)   The physical nature of these available but not operating facilities is such that they
           cannot be started up and/or synchronized in sufficient time to assist in addressing the
           disturbance. The facilities need to be synchronized to the IMO-controlled grid at the
           time of the disturbance. Refer to Attachment B for a representative example where an
           additional supply resource was on-line at the time of a disturbance.
      d) Domestic resources are not operating at these times typically because the pre-dispatch
         signals are insufficient to convince the market participant that they will make enough
         market revenues and profit to justify opertaion. The market participant may then either
         remove their offers, or increase their offer prices so that if they are scheduled and
         dispatched, they will earn sufficient revenue. The resource may then become
         uneconomic and be removed from the pre-dispatch and real-time schedule. The
         participant has in effect, and for good reason, “run-away” from the market.


1
  Changes could include failed intertie transactions, demand being less or greater than forecast, forced outages or
deratings of generation facilities.
2
  The counter-intuitive pricing can occur if the disturbance or changes requires the IMO to reduce manually the
market requirements for operating reserve and utilize out-of-market sources of operating reserve.


February 25, 2003                                                                                                     1
                                                    DRAFT
                                                                                             IMOTP 121-9b
       e)   Additional feedback from market participants is that market price stability and
            predictability is very important to the consumers of electricity.
       f)   In order to make the market and operation of the IMO-controlled grid more robust and
            predictable, the IMO is proposing that a mechanism be introduced that would provide
            market-based incentives for “shock absorption” capability in the form of domestic
            dispatchable generation. The IMO believes that market-based incentives are preferable
            to “command and control” measures so that the provision of “shock absorption”
            dispatchable generation is transparent, predictable and available to any dispatchable
            generator.
       g) The purpose of this discussion paper is to present a number of these possible market-
          based mechanisms for discussion with stakeholders. The goal of these discussions
          would be to develop/identify a mechanism that meets the needs of the market, market
          participants and the IMO.


2.     Intent of Initiative
       There appear to be a number of goals or objectives that would need to be met in order for a
       proposed incentive to be acceptable and successful.
       a)   Address the three key pricing issues: pre-dispatch price not being a reliable indication
            of real-time price; counter-intuitive pricing in times of market shortages; size, content
            and variability of hourly uplift charges.
       b) Increase the availability of domestic dispatchable resources in real-time to address the
          disturbances noted above, resulting in reduced need for use of out-of-market sources of
          operating reserve and emergency energy purchases.
       c)   Provide a measure of price stability, both in terms of reduced price spikes and fewer
            instances of counter-intuitive pricing.
       d) Reduce resource dispatch volatility.
       e)   Provide sufficient incentive to the domestic dispatchable resources.


3.     Option 1 – Guarantee of Generation Start-up, Speed No-Load and Minimum Generation
       Costs on a Per-Start Basis3
       a)   The IMO-administered market would provide a guarantee that a market participant
            would recover the “start-up”, “speed no-load” and minimum generation costs from the
            market for an eligible and scheduled generation facility on a per-start basis. This
            guarantee would be comparable, in principle, to the New York market guarantee of
            similar costs.
       b) All generation facilities, except those designated as “quick-start”, will be eligible for
          this guarantee. “Quick-start” units would not be eligible, as recovery of “start-up”,
          “speed no-load” and minimum generation costs is typically not an issue with
          commitment decisions of these resources.
3
    This option has been presented and discussed at the MOSC meeting on December 18, 2002.


February 25, 2003                                                                                       2
                                              DRAFT
                                                                                     IMOTP 121-9b
     c)   The market participant shall, if they wish their facility to be eligible for this guarantee,
          provide the IMO with the “start-up”, “speed no-load” and minimum generation costs for
          their facility. Definition of these costs will need to be developed in consultation with
          market participants. The IMO would have the right to audit the costs provided by the
          participant as to the accuracy of the costs, to protect the market from making payments
          greater than the actual “start-up”, “speed no-load” and minimum generation costs
          incurred.
     d) To be eligible for the guarantee on a per-start basis, the generation facility would need
        to be scheduled in the three hour-ahead pre-dispatch schedule and meet its real-time
        dispatch instructions. The three-hour ahead pre-dispatch schedule is used as the
        “commitment schedule” as it allows the market participant to meet the existing market
        rules in regards to synchronization.
     e)   An eligible facility would be guaranteed a minimum run-time once the facility becomes
          synchronized. This minimum run-time would be specified ahead of time by the
          generator. The guarantee of a minimum run-time is intended to meet operating
          requirements of generation facilities.
     f)   The facility would receive market prices for any energy and operating reserve scheduled
          and provided and would receive congestion management settlement credit (CMSC)
          payments where applicable.
     g) On a per-start basis, the IMO will determine if the market revenue (energy, operating
        reserve, CMSC payments) for the facility exceeds the sum of the submitted facility
        “start-up”, “speed no-load”, minimum generation costs and its offer prices times energy
        produced. If market revenues were less than this sum, the market participant would
        receive an additional payment from the market equal to the difference. These payments
        would be recovered from other market participants as a monthly uplift charge.
     h) Pros:
           Similar to guarantee provided by New York ISO, and so will contribute to
            harmonization of Ontario and neighbouring markets.
           Provide more level playing field for domestic and New York resources to compete
           The three hour-ahead commitment would represent an evolutionary step to a
            potential day-ahead commitment market;
           Expected to result in market participant(s) committing an additional domestic
            resource(s) on the basis of the pre-dispatch signals. This additional resource(s) would
            be the “shock absorber” i.e. more market resources would be available to meet
            market demands, resulting in less price and dispatch volatility, reduced need for use
            of out-of-market sources of operating reserve.
           Reduce reliance on imports for energy, reducing potential for IOG payments
     i) Cons:
           Would require new IMO and market participant settlement processes and procedures
            to determine need for and payment of guarantee.



February 25, 2003                                                                                    3
                                             DRAFT
                                                                                  IMOTP 121-9b
           Initial reaction from generators not supportive: cost guarantee not adequate to offset
            potential for increased wear-and-tear of units and potential lost market revenue; use
            of market revenues on per-start basis in comparison to costs is not appropriate.
           Increased monthly uplift charges.


4.   Option 2 – Guarantee of Generation Start-up, Speed No-Load and Minimum Generation
     Costs over a Minimum Run-Time
     a)   This option is a variation of option 1. It attempts to address the expressed generator
          concern that use of market revenues on per-start basis in comparison to costs is not
          appropriate. Under this option, the determination of the need for the guarantee would be
          based on market revenues earned over the minimum run-time for the facility specified
          by the market participant. All other features of Option 1 would apply.
     b) Pros:
           Same as Option 1.
           Criteria for evaluating payment of guarantee may be more appropriate and
            acceptable to generators.
     c) Cons:
           Would require new IMO and market participant settlement processes and procedures
            to determine need for and payment of guarantee.
           Increased monthly uplift charges, potentially more than Option 1, as minimum run-
            time criteria may increase frequency of payout of guarantee.


5.   Option 3: Increase 10 Minute Synchronized Operating Reserve Requirement
     a)   The IMO would increase the 10-minute synchronized operating reserve requirement.
          For example, the IMO could increase the requirement by 250 MW, from 230/280 MW
          to 480/530 MW. The total 10-minute operating reserve requirement would remain at
          920/1120 MW, and the 30-minute operating reserve requirement would remain at 460
          MW.
     b) Synchronized operating reserve must be provided by domestic generation facilities.
        Increasing the 10-minute synchronized operating reserve requirement would provide
        incentives for more facilities to be synchronized in order to be eligible to provide 10-
        minute synchronized reserve.
     c)   Pros:
           Would not require new IMO or market participant settlement processes and
            procedures.
           May attract additional domestic generation to market in order to get 10-minute
            synchronized reserve payments.
     d) Cons:


February 25, 2003                                                                                    4
                                             DRAFT
                                                                                 IMOTP 121-9b
           Potential to increase reliance on imports to meet energy requirements, as
            synchronized resources may be “backed-off” from providing energy in order to
            provide synchronized operating reserve.
           May simply move 10-minute non-synchronized operating reserve to 10-minute
            synchronized operating reserve, thereby not bringing any additional resources to
            market.
           Reduced 10-minute non-synchronized operating reserve market could negatively
            impact market participants whose dispatchable facilities cannot provide
            synchronized operating reserve e.g. dispatchable loads.
           Potential for higher operating reserve prices due to increased requirement for more
            valuable, and hence costly, synchronized operating reserve;
           Potential for higher energy market prices due to co-optimization




February 25, 2003                                                                                 5
                                                                                   DRAFT
                                                                                                                                        IMOTP 121-9b
                                                                               Attachment A

                                    Example of Impact of Not Having Additional Generation Capacity On-Line


                                                                              September 26, 2002

                       250                                                                                                                            30.00%



                                                                                                                                                      25.00%

                       200
                                                                                                                                                      20.00%
Energy Price ($/MWh)




                                                                                                                                                      15.00%




                                                                                                                                                                   Supply Cushion
                       150


                                                                                                                                                      10.00%


                       100
                                                                                                                                                      5.00%



                                                                                                                                                      0.00%
                           50

                                                                                                                                                      -5.00%



                           0                                                                                                                          -10.00%
                                1   2   3   4   5   6     7    8    9    10   11   12   13   14    15   16   17   18   19   20    21   22   23   24
                                                                                    Hour

                                                        Real-Time HOEP         Pre-Dispatch HOEP        Domestic Supply Cushion




                       Domestic Supply Cushion % =                       EO-(ED+OR) x 100%
                                                                           ED+OR
                       Where:
                       EO4 = total amount of domestic available energy offered
                       ED5 = total amount of energy demanded
                       OR = operating reserve requirements


                       4
                         EO measures only “available” energy offers in the sense that it does not include offered quantities from non-quick
                       start units that are not synchronized, nor does it include offered quantities that are made unavailable due to an
                       unplanned outage or derating.
                       5
                        ED consists of the non-dispatchable load component of demand plus the quantity demand by dispatchable loads
                       and exporters bid at a price of $2000.


                       February 25, 2003                                                                                                                       6
                                            DRAFT
                                                                                 IMOTP 121-9b


                                  Attachment A (continued)

         Example of Impact of Not Having Additional Generation Capacity On-Line



On this day the following disturbances occurred:
 Significant failures of intertie transactions throughout the day: e.g. net 300 MW imports in
  hour 10; net 360 MW imports in hour 16; net 440 MW imports in hour 20

The impacts of these disturbances were price spikes of between $110 and $190 in hours 10, 11,
13 and 20. During these hours, the available capacity from non-quick start units that was offered
but not synchronized was between 500 MW and 1000 MW.




February 25, 2003                                                                                7
                                                                              DRAFT
                                                                                                                               IMOTP 121-9b
                                                             Attachment A (continued)

                                   Example of Impact of Not Having Additional Generation Capacity On-Line



                                                                  September 24, 2002

                     250




                     200
Energy Price $/MWh




                     150




                     100




                      50




                       0
                           1   2     3   4   5   6   7   8   9      10   11    12    13   14   15   16     17   18   19   20   21   22   23   24
                                                                          Hour of the Day

                                                                 Pre-Dispatch HOEP        Real-Time HOEP



                       On this day the following disturbances occurred:
                        Ontario demand was approximately 170 MW above forecast from hours 7 through 11;
                        Failures of intertie transactions throughout the day: e.g. net 100 MW imports in hours 8, 12,
                         14 and 20; net 300 MW in hour 21.

                       In response to these disturbances the IMO utilized out-of market sources of 30-minute operating
                       reserve in the following amounts: 100-200 MW in hours 7 through 11; 20-80 MW in hours 19
                       and 20.

                       In hours 7 through 11, there was approximately 1000 MW of available capacity from non-quick
                       start units that was offered but not synchronized. In hours 19 and 20, there was approximately
                       500 MW of available capacity from non-quick start units that was offered but not synchronized.




                       February 25, 2003                                                                                                           8
                                                                                   DRAFT
                                                                                                                                       IMOTP 121-9b
                                                                              Attachment B

                                     Example of Impact of Having Additional Generation Capacity On-Line



                                                                             January 13, 2003

                       250                                                                                                                           30.00%



                                                                                                                                                     25.00%
                       200

                                                                                                                                                     20.00%
Energy Price ($/MWh)




                                                                                                                                                              Supply Cushion
                       150
                                                                                                                                                     15.00%



                                                                                                                                                     10.00%
                       100


                                                                                                                                                     5.00%

                        50
                                                                                                                                                     0.00%



                         0                                                                                                                           -5.00%
                             1   2    3    4   5   6    7    8    9     10   11   12   13   14   15   16   17   18   19   20   21     22   23   24
                                                                             Hour of the Day


                                                       Real-Time HOEP             Pre-Dispatch HOEP         Domestic Supply Cushion



                       Refer to Attachment A for description of Domestic Supply Cushion.

                       On this day the following disturbances occurred:
                        At approximately 08:00, there was a forced outage/derating of a generation facility, resulting
                         in a sudden loss of generation of approximately 500 MW
                        At approximately 10:30, there a forced outage/derating of a generation facility, resulting in a
                         loss of generation capacity of approximately 300 MW
                        At approximately 11:30, there was a forced outage/derating of a generation facility, resulting
                         in a sudden loss of generation of approximately 500 MW

                       Through all these disturbances, the only apparent market pricing impact was in hour 9 where the
                       real-time HOEP spiked at 111 $/MWh. For the remainder of the day, the pre-dispatch energy
                       price was a good indication of the real-time energy price.




                       February 25, 2003                                                                                                                      9

				
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Description: draft imotp 121 9b discussion paper market incentives to increase